Processes for the Separation of Methane from a Gas Stream

ABSTRACT

Processes for the catalytic conversion of a carbonaceous composition into a gas stream comprising methane are provided. In addition, the processes provide for the generation of a hydrogen-enriched gas stream and, optionally, a carbon monoxide-enriched gas stream, which can be mixed or used separately as an energy source for subsequent catalytic gasification processes.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. §119 from U.S.Provisional Application Ser. No. 61/041,307 (filed Apr. 1, 2008), thedisclosure of which is incorporated by reference herein for all purposesas if fully set forth.

FIELD OF THE INVENTION

The present invention relates to processes for catalytically convertinga carbonaceous feedstock into a plurality of gaseous products containedin a gas stream, and for separating methane from the gas stream. Inparticular, the invention relates to continuous processes forcatalytically converting a carbonaceous feedstock into a plurality ofgaseous products contained in a gas stream, and for separating methanefrom carbon monoxide and hydrogen in a manner that permits the recyclingof hydrogen and carbon monoxide use in the catalytic gasificationprocesses.

BACKGROUND OF THE INVENTION

In view of numerous factors such as higher energy prices andenvironmental concerns, the production of value-added gaseous productsfrom lower-fuel-value carbonaceous feedstocks, such as biomass, coal andpetroleum coke, is receiving renewed attention. The catalyticgasification of such materials to produce methane and other value-addedgases is disclosed, for example, in U.S. Pat. No. 3,828,474, U.S. Pat.No. 3,998,607, U.S. Pat. No. 4,057,512, U.S. Pat. No. 4,092,125, U.S.Pat. No. 4,094,650, U.S. Pat. No. 4,204,843, U.S. Pat. No. 4,468,231,U.S. Pat. No. 4,500,323, U.S. Pat. No. 4,541,841, U.S. Pat. No.4,551,155, U.S. Pat. No. 4,558,027, U.S. Pat. No. 4,606,105, U.S. Pat.No. 4,617,027, U.S. Pat. No. 4,609,456, U.S. Pat. No. 5,017,282, U.S.Pat. No. 5,055,181, U.S. Pat. No. 6,187,465, U.S. Pat. No. 6,790,430,U.S. Pat. No. 6,894,183, U.S. Pat. No. 6,955,695, US2003/0167961A1,US2006/0265953A1, US2007/000177A1, US2007/083072A1, US2007/0277437A1 andGB1599932.

Reaction of lower-fuel-value carbonaceous feedstocks under conditionsdescribed in the above references typically yields a crude product gasand a char. The crude product gas typically comprises an amount ofparticles, which are removed from the gas stream to produce a gaseffluent. This gas effluent typically contains a mixture of gases,including, but not limited to, methane, carbon dioxide, hydrogen, carbonmonoxide, hydrogen sulfide, ammonia, unreacted steam, entrained fines,and other contaminants such as COS. Through processes known in the art,the gas effluent can be treated to remove carbon dioxide, hydrogensulfide, steam, entrained fines, COS, and other contaminants, yielding acleaned gas stream comprising methane, carbon monoxide, and hydrogen.Carbon monoxide may optionally be removed or converted at some pointprior to hydrogen separation, yielding a cleaned gas stream comprisingmethane and hydrogen.

For some applications, it may be desirable to recover a gas stream thatis enriched in methane. In some situations, it may even be desirable torecover a gas stream that almost entirely comprises methane. In suchsituations, the cleaned gas stream must undergo additional processing toremove substantially all of the hydrogen and, if present, carbonmonoxide. On the other hand, hydrogen and mixtures of hydrogen andcarbon monoxide (“syngas”) have utility as an energy or raw materialsource.

In some situations, such as in the context of the present invention, itmay be desirable to collect hydrogen and, optionally, carbon monoxideand recycle them as a raw material or energy source for a subsequentcatalytic gasification process. Thus, there is a continued need forprocesses which permit the efficient recovery of methane, and alsopermit recovery of separate gas streams of carbon monoxide and hydrogen.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a block diagram that illustrates a continuous process forgasification of a carbonaceous feedstock, where the process includesseparation of methane from hydrogen and, optionally, carbon monoxide,and the recycle of hydrogen and carbon monoxide for use in the catalyticgasification process.

SUMMARY OF THE INVENTION

In a first aspect, the present invention provides a process forconverting a carbonaceous feedstock into a plurality of gaseous productscontained in a gas stream, and for separating hydrogen and methane fromthe gas stream, the process comprising the steps of: (a) supplying acarbonaceous feedstock to a gasification reactor; (b) reacting thecarbonaceous feedstock in the gasification reactor in the presence ofsteam and a gasification catalyst and under suitable temperature andpressure to form a first gas stream comprising methane, hydrogen, carbonmonoxide, carbon dioxide, and one or more additional gaseousby-products; (c) removing a substantial portion of the carbon dioxideand a substantial portion of the one or more additional gaseousby-products from the first gas stream to produce a second gas streamcomprising methane, hydrogen, and optionally carbon monoxide; (d) atleast partially separating hydrogen from the second gas stream to form ahydrogen-enriched gas stream and a hydrogen-depleted gas stream, whereinthe hydrogen-depleted gas stream comprises methane, optionally carbonmonoxide and up to about 4 mol % hydrogen; wherein, if the heating valueof the hydrogen-depleted gas stream is less than 950 btu/scf (drybasis), and if the hydrogen-depleted gas stream comprises 1000 ppm ormore of carbon monoxide: (1) at least partially separating carbonmonoxide from the hydrogen-depleted gas stream to form (i) a carbonmonoxide-enriched gas stream and (ii) a methane enriched gas streamhaving a heating value of at least 950 btu/scf (dry basis); or (2) atleast partially methanating the carbon monoxide in the hydrogen-depletedgas stream to form a methane-enriched gas stream.

In a second aspect, the present invention provides a process forconverting a carbonaceous feedstock into a plurality of gaseous productscontained in a gas stream, and for separating hydrogen and methane fromthe gas stream, the process comprising the steps of: (a) supplying afirst carbonaceous feedstock to a reactor; (b) at least partiallycombusting the first carbonaceous feedstock in the reactor in thepresence of oxygen and under suitable temperature and pressure so as togenerate (i) heat energy and (ii) a combustion gas stream comprisinghydrogen, carbon monoxide, and carbon dioxide; (c) using the heat energyfrom the combustion of the first carbonaceous feedstock to generatesteam; (d) introducing at least a portion of the steam, at least aportion of the combustion gas stream, a second carbonaceous feedstockand a gasification catalyst to a gasification reactor; (e) reacting thesecond carbonaceous feedstock in the gasification reactor in thepresence of steam and the gasification catalyst under suitabletemperature and pressure to form a first gas stream comprising methane,hydrogen, carbon monoxide, carbon dioxide and one or more additionalgaseous by-products; (f) removing a substantial portion of the carbondioxide and a substantial portion of the one or more gaseous by-productsfrom the first gas stream to produce a second gas stream comprisingmethane, hydrogen and optionally carbon monoxide; (g) at least partiallyseparating hydrogen from the second gas stream to form ahydrogen-enriched gas stream and a hydrogen-depleted gas stream, whereinthe hydrogen-depleted gas stream comprises methane, optionally carbonmonoxide and up to about 4 mol % hydrogen; wherein, if the heating valueof the hydrogen-depleted gas stream is less than 950 btu/scf (drybasis), and if the hydrogen-depleted gas stream comprises 1000 ppm ormore of carbon monoxide: (1) at least partially separating carbonmonoxide from the hydrogen-depleted gas stream to form (i) a carbonmonoxide-enriched gas stream and (ii) a methane enriched gas streamhaving a heating value of at least 950 btu/scf (dry basis); or (2) atleast partially methanating the carbon monoxide in the hydrogen-depletedgas stream to form a methane-enriched gas stream.

DETAILED DESCRIPTION

The present invention relates to processes for converting a carbonaceousfeedstock into a plurality of gaseous products contained in a gasstream, and for separating methane from the other gaseous products inthe gas stream. The present invention provides processes for separatingmethane in a manner that allows for the recovery of a hydrogen gasstream and, optionally, a separate gas stream of carbon monoxide.Although the processes of the invention can be employed in a variety ofgasification processes, the processes are particularly useful insituations where it is desirable to recover a substantially pure streamof methane gas and a substantially pure stream of hydrogen gas. In thisway, the hydrogen can be used as an energy source or raw material, orcan be mixed with controlled quantities of carbon monoxide to generate asyngas tailored to the desired application. Particularly, the inventionprovides a continuous catalytic gasification process that yieldspipeline-grade methane and also recovers hydrogen, and optionally carbonmonoxide, for recycle in the catalytic gasification process.

The present invention can be practiced, for example, using any of thedevelopments to catalytic gasification technology disclosed in commonlyowned US2007/0000177A1, US2007/0083072A1, US2007/0277437A1 andUS2009/0048476A1; and U.S. patent application Ser. Nos. 12/234,012(filed 19 Sep. 2008) and 12/234,018 (filed 19 Sep. 2008).

Moreover, the present invention can be practiced in conjunction with thesubject matter of the following US patent applications, each of whichwas filed on Dec. 28, 2008: Ser. No. 12/342,554, entitled “CATALYTICGASIFICATION PROCESS WITH RECOVERY OF ALKALI METAL FROM CHAR”; Ser. No.12/342,565, entitled “PETROLEUM COKE COMPOSITIONS FOR CATALYTICGASIFICATION”; Ser. No. 12/342,578, entitled “COAL COMPOSITIONS FORCATALYTIC GASIFICATION”; Ser. No. 12/342,596, entitled “PROCESSES FORMAKING SYNTHESIS GAS AND SYNGAS-DERIVED PRODUCTS”; Ser. No. 12/342,608,entitled “PETROLEUM COKE COMPOSITIONS FOR CATALYTIC GASIFICATION”; Ser.No. 12/342,628, entitled “PROCESSES FOR MAKING SYNGAS-DERIVED PRODUCTS”;Ser. No. 12/342,663, entitled “CARBONACEOUS FUELS AND PROCESSES FORMAKING AND USING THEM”; Ser. No. 12/342,715, entitled “CATALYTICGASIFICATION PROCESS WITH RECOVERY OF ALKALI METAL FROM CHAR”; Ser. No.12/342,736, entitled “CATALYTIC GASIFICATION PROCESS WITH RECOVERY OFALKALI METAL FROM CHAR”; Ser. No. 12/343,143, entitled “CATALYTICGASIFICATION PROCESS WITH RECOVERY OF ALKALI METAL FROM CHAR”; Ser. No.12/343,149, entitled “STEAM GENERATING SLURRY GASIFIER FOR THE CATALYTICGASIFICATION OF A CARBONACEOUS FEEDSTOCK”; and Ser. No. 12/343,159,entitled “CONTINUOUS PROCESSES FOR CONVERTING CARBONACEOUS FEEDSTOCKINTO GASEOUS PRODUCTS”.

Further, the present invention can be practiced in conjunction with thesubject matter of the following US patent applications, each of whichwas filed Feb. 27, 2008: Ser. No. 12/395,293, entitled “PROCESSES FORMAKING ABSORBENTS AND PROCESSES FOR REMOVING CONTAMINANTS FROM FLUIDSUSING THEM”; Ser. No. 12/395,309, entitled “STEAM GENERATION PROCESSESUTILIZING BIOMASS FEEDSTOCKS”; Ser. No. 12/395,320, entitled “REDUCEDCARBON FOOTPRINT STEAM GENERATION PROCESSES”; Ser. No. 12/395,330,entitled “PROCESS AND APPARATUS FOR THE SEPARATION OF METHANE FROM A GASSTREAM”; Ser. No. 12/395,344, entitled “SELECTIVE REMOVAL AND RECOVERYOF ACID GASES FROM GASIFICATION PRODUCTS”; Ser. No. 12/395,348, entitled“COAL COMPOSITIONS FOR CATALYTIC GASIFICATION”; Ser. No. 12/395,353,entitled “COAL COMPOSITIONS FOR CATALYTIC GASIFICATION”; Ser. No.12/395,372, entitled “CO-FEED OF BIOMASS AS SOURCE OF MAKEUP CATALYSTSFOR CATALYTIC COAL GASIFICATION”; Ser. No. 12/395,381, entitled“COMPACTOR-FEEDER”; Ser. No. 12/395,385, entitled “CARBONACEOUS FINESRECYCLE”; Ser. No. 12/395,429, entitled “BIOMASS CHAR COMPOSITIONS FORCATALYTIC GASIFICATION”; Ser. No. 12/395,433, entitled “CATALYTICGASIFICATION PARTICULATE COMPOSITIONS”; and Ser. No. 12/395,447,entitled “BIOMASS COMPOSITIONS FOR CATALYTIC GASIFICATION”.

The present invention can also be practiced in conjunction with thesubject matter of U.S. patent application Ser. No. ______ filedconcurrently herewith (attorney docket no. FN-0033, entitled “SOUR SHIFTPROCESS FOR THE REMOVAL OF CARBON MONOXIDE FROM A GAS STREAM”).

All publications, patent applications, patents and other referencesmentioned herein, including but not limited to those referenced above,if not otherwise indicated, are explicitly incorporated by referenceherein in their entirety for all purposes as if fully set forth.

Unless otherwise defined, all technical and scientific terms used hereinhave the same meaning as commonly understood by one of ordinary skill inthe art to which this invention belongs. In case of conflict, thepresent specification, including definitions, will control.

Except where expressly noted, trademarks are shown in upper case.

Although methods and materials similar or equivalent to those describedherein can be used in the practice or testing of the present invention,suitable methods and materials are described herein.

Unless stated otherwise, all percentages, parts, ratios, etc., are byweight.

When an amount, concentration, or other value or parameter is given as arange, or a list of upper and lower values, this is to be understood asspecifically disclosing all ranges formed from any pair of any upper andlower range limits, regardless of whether ranges are separatelydisclosed. Where a range of numerical values is recited herein, unlessotherwise stated, the range is intended to include the endpointsthereof, and all integers and fractions within the range. It is notintended that the scope of the present invention be limited to thespecific values recited when defining a range.

When the term “about” is used in describing a value or an end-point of arange, the invention should be understood to include the specific valueor end-point referred to.

As used herein, the terms “comprises,” “comprising,” “includes,”“including,” “has,” “having” or any other variation thereof, areintended to cover a non-exclusive inclusion. For example, a process,method, article, or apparatus that comprises a list of elements is notnecessarily limited to only those elements but can include otherelements not expressly listed or inherent to such process, method,article, or apparatus. Further, unless expressly stated to the contrary,“or” refers to an inclusive or and not to an exclusive or. For example,a condition A or B is satisfied by any one of the following: A is true(or present) and B is false (or not present), A is false (or notpresent) and B is true (or present), and both A and B are true (orpresent).

The use of “a” or “an” to describe the various elements and componentsherein is merely for convenience and to give a general sense of theinvention. This description should be read to include one or at leastone and the singular also includes the plural unless it is obvious thatit is meant otherwise.

The materials, methods, and examples herein are illustrative only and,except as specifically stated, are not intended to be limiting.

Gasification Methods

The gas recovery methods of the present invention are particularlyuseful in integrated gasification processes for converting carbonaceousfeedstocks, such as petroleum coke, liquid petroleum residue,asphaltenes, biomass and/or coal to combustible gases, such as methane.

The gasification reactors for such processes are typically operated atmoderately high pressures and temperature, requiring introduction of acarbonaceous material (i.e., a feedstock) to the reaction zone of thegasification reactor while maintaining the required temperature,pressure, and flow rate of the feedstock. Those skilled in the art arefamiliar with feed systems for providing feedstocks to high pressureand/or temperature environments, including, star feeders, screw feeders,rotary pistons, and lock-hoppers. It should be understood that the feedsystem can include two or more pressure-balanced elements, such as lockhoppers, which would be used alternately.

The catalyzed feedstock is provided to the catalytic gasifier from afeedstock preparation operation, and generally comprises a particulatecomposition of a crushed carbonaceous material and a gasificationcatalyst, as discussed below. In some instances, the catalyzed feedstockcan be prepared at pressures conditions above the operating pressure ofcatalytic gasifier. Hence, the catalyzed feedstock can be directlypassed into the catalytic gasifier without further pressurization.

Any of several catalytic gasifiers can be utilized. Suitable gasifiersinclude counter-current fixed bed, co-current fixed bed, fluidized bed,entrained flow, and moving bed reactors. A catalytic gasifier forgasifying liquid feeds, such as liquid petroleum residues, is disclosedin previously incorporated U.S. Pat. No. 6,955,695.

The pressure in the catalytic gasifier typically can be from about 10 toabout 100 atm (from about 150 to about 1500 psig). The gasificationreactor temperature can be maintained around at least about 450° C., orat least about 600° C., or at least about 900° C., or at least about750° C., or about 600° C. to about 700° C.; and at pressures of at leastabout 50 psig, or at least about 200 psig, or at least about 400 psig,to about 1000 psig, or to about 700 psig, or to about 600 psig.

The gas utilized in the catalytic gasifier for pressurization andreactions of the particulate composition comprises steam, andoptionally, oxygen or air, and is supplied, as necessary, to the reactoraccording to methods known to those skilled in the art.

For example, steam can be supplied to the catalytic gasifier from any ofthe steam boilers known to those skilled in the art can supply steam tothe reactor. Such boilers can be powered, for example, through the useof any carbonaceous material such as powdered coal, biomass etc., andincluding but not limited to rejected carbonaceous materials from theparticulate composition preparation operation (e.g., fines, supra).Steam can also be supplied from a second gasification reactor coupled toa combustion turbine where the exhaust from the reactor is thermallyexchanged to a water source and produce steam. Alternatively, the steammay be provided to the gasification reactor as described previouslyincorporated U.S. patent application Ser. Nos. 12/343,149, 12/395,309and 12/395,320.

Recycled steam from other process operations can also be used forsupplementing steam to the catalytic gasifier. For example in thepreparation of the catalyzed feedstock, when slurried particulatecomposition are dried with a fluid bed slurry drier, as discussed below,then the steam generated can be fed to the catalytic gasificationreactor.

The small amount of heat input that may be required for the catalyticgasifier can be provided by superheating a gas mixture of steam andrecycle gas feeding the gasification reactor by any method known to oneskilled in the art. In one method, compressed recycle gas of CO and H₂can be mixed with steam and the resulting steam/recycle gas mixture canbe further superheated by heat exchange with the catalytic gasifiereffluent followed by superheating in a recycle gas furnace.

A methane reformer can be optionally included in the process tosupplement the recycle CO and H₂ stream and the exhaust from the slurrygasifier to ensure that enough recycle gas is supplied to the reactor sothat the net heat of reaction is as close to neutral as possible (onlyslightly exothermic or endothermic), in other words, that the catalyticgasifier is run under substantially thermally neutral conditions. Insuch instances, methane can be supplied for the reformer from themethane product, as described below.

Reaction of the catalyzed feedstock in the catalytic gasifier, under thedescribed conditions, provides a crude product gas and a char from thecatalytic gasification reactor.

The char produced in the catalytic gasifier processes is typicallyremoved from the catalytic gasifier for sampling, purging, and/orcatalyst recovery in a continuous or batch-wise manner. Methods forremoving char are well known to those skilled in the art. One suchmethod taught by EP-A-0102828, for example, can be employed. The charcan be periodically withdrawn from the catalytic gasification reactorthrough a lock hopper system, although other methods are known to thoseskilled in the art.

Often, the char from the catalytic gasifier is directed to a catalystrecovery and recycle process. Processes have been developed to recoveralkali metal from the solid purge in order to reduce raw material costsand to minimize environmental impact of a catalytic gasificationprocess. For example, the char can be quenched with recycle gas andwater and directed to a catalyst recycling operation for extraction andreuse of the alkali metal catalyst. Particularly useful recovery andrecycling processes are described in U.S. Pat. No. 4,459,138, as well aspreviously incorporated U.S. Pat. No. 4,057,512 and US2007/0277437A1,and previously incorporated U.S. patent application Ser. Nos.12/342,554, 12/342,715, 12/342,736 and 12/343,143. Reference can be hadto those documents for further process details.

Upon completion of catalyst recovery, both the char, substantially freeof the gasification catalysts and the recovered catalyst (as a solutionor solid) can be directed to the feedstock preparation operationcomprising a catalyzed feedstock preparation process and a slurryfeedstock preparation process.

Carbonaceous Feedstock

The term “carbonaceous feedstock” as used herein includes a carbonsource, typically coal, petroleum coke, asphaltene and/or liquidpetroleum residue, but may broadly include any source of carbon suitablefor gasification, including biomass.

The term “petroleum coke” as used herein includes both (i) the solidthermal decomposition product of high-boiling hydrocarbon fractionsobtained in petroleum processing (heavy residues —“resid petcoke”) and(ii) the solid thermal decomposition product of processing tar sands(bituminous sands or oil sands —“tar sands petcoke”). Such carbonizationproducts include, for example, green, calcined, needle and fluidized bedpetroleum coke.

Resid petcoke can be derived from a crude oil, for example, by cokingprocesses used for upgrading heavy-gravity residual crude oil, whichpetroleum coke contains ash as a minor component, typically about 1.0 wt% or less, and more typically about 0.5 wt % of less, based on theweight of the coke. Typically, the ash in such lower-ash cokespredominantly comprises metals such as nickel and vanadium.

Tar sands petcoke can be derived from an oil sand, for example, bycoking processes used for upgrading oil sand. Tar sands petcoke containsash as a minor component, typically in the range of about 2 wt % toabout 12 wt %, and more typically in the range of about 4 wt % to about12 wt %, based on the overall weight of the tar sands petcoke.Typically, the ash in such higher-ash cokes predominantly comprisesmaterials such as compounds of silicon and/or aluminum.

The petroleum coke can comprise at least about 70 wt % carbon, at leastabout 80 wt % carbon, or at least about 90 wt % carbon, based on thetotal weight of the petroleum coke. Typically, the petroleum cokecomprises less than about 20 wt % percent inorganic compounds, based onthe weight of the petroleum coke.

The term “asphaltene” as used herein is an aromatic carbonaceous solidat room temperature, and can be derived, from example, from theprocessing of crude oil and crude oil tar sands.

The term “liquid petroleum residue” as used herein includes both (i) theliquid thermal decomposition product of high-boiling hydrocarbonfractions obtained in petroleum processing (heavy residues —“residliquid petroleum residue”) and (ii) the liquid thermal decompositionproduct of processing tar sands (bituminous sands or oil sands —“tarsands liquid petroleum residue”). The liquid petroleum residue issubstantially non-solid at room temperature; for example, it can takethe form of a thick fluid or a sludge.

Resid liquid petroleum residue can also be derived from a crude oil, forexample, by processes used for upgrading heavy-gravity crude oildistillation residue. Such liquid petroleum residue contains ash as aminor component, typically about 1.0 wt % or less, and more typicallyabout 0.5 wt % of less, based on the weight of the residue. Typically,the ash in such lower-ash residues predominantly comprises metals suchas nickel and vanadium.

Tar sands liquid petroleum residue can be derived from an oil sand, forexample, by processes used for upgrading oil sand. Tar sands liquidpetroleum residue contains ash as a minor component, typically in therange of about 2 wt % to about 12 wt %, and more typically in the rangeof about 4 wt % to about 12 wt %, based on the overall weight of theresidue. Typically, the ash in such higher-ash residues predominantlycomprises materials such as compounds of silicon and/or aluminum.

The term “coal” as used herein means peat, lignite, sub-bituminous coal,bituminous coal, anthracite, or mixtures thereof. In certainembodiments, the coal has a carbon content of less than about 85%, orless than about 80%, or less than about 75%, or less than about 70%, orless than about 65%, or less than about 60%, or less than about 55%, orless than about 50% by weight, based on the total coal weight. In otherembodiments, the coal has a carbon content ranging up to about 85%, orup to about 80%, or up to about 75% by weight, based on total coalweight. Examples of useful coals include, but are not limited to,Illinois #6, Pittsburgh #8, Beulah (ND), Utah Blind Canyon, and PowderRiver Basin (PRB) coals. Anthracite, bituminous coal, sub-bituminouscoal, and lignite coal may contain about 10 wt %, from about 5 to about7 wt %, from about 4 to about 8 wt %, and from about 9 to about 11 wt %,ash by total weight of the coal on a dry basis, respectively. However,the ash content of any particular coal source will depend on the rankand source of the coal, as is familiar to those skilled in the art. See,e.g., Coal Data: A Reference, Energy Information Administration, Officeof Coal, Nuclear, Electric and Alternate Fuels, U.S. Department ofEnergy, DOE/EIA-0064(93), February 1995.

The term “ash” as used herein includes inorganic compounds that occurwithin the carbon source. The ash typically includes compounds ofsilicon, aluminum, calcium, iron, vanadium, sulfur, and the like. Suchcompounds include inorganic oxides, such as silica, alumina, ferricoxide, etc., but may also include a variety of minerals containing oneor more of silicon, aluminum, calcium, iron, and vanadium. The term“ash” may be used to refer to such compounds present in the carbonsource prior to gasification, and may also be used to refer to suchcompounds present in the char after gasification.

Catalyst-Loaded Carbonaceous Feedstock

The carbonaceous composition is generally loaded with an amount of analkali metal compound to promote the steam gasification to methane.Typically, the quantity of the alkali metal compound in the compositionis sufficient to provide a ratio of alkali metal atoms to carbon atomsranging from about 0.01, or from about 0.02, or from about 0.03, or fromabout 0.04, to about 0.06, to about 0.07, or to about 0.08, or to about0.1. Further, the alkali metal is typically loaded onto a carbon sourceto achieve an alkali metal content of from about 3 to about 10 timesmore than the combined ash content of the carbonaceous material (e.g.,coal and/or petroleum coke), on a mass basis.

Alkali metal compounds suitable for use as a gasification catalystinclude compounds selected from the group consisting of alkali metalcarbonates, bicarbonates, formates, oxalates, amides, hydroxides,acetates, halides, nitrates, sulfides, and polysulfides. For example,the catalyst can comprise one or more of Na₂CO₃, K₂CO₃, Rb₂CO₃, Li₂CO₃,Cs₂CO₃, NaOH, KOH, RbOH, or CsOH, and particularly, potassium carbonateand/or potassium hydroxide.

Any methods known to those skilled in the art can be used to associateone or more gasification catalysts with the carbonaceous composition.Such methods include, but are not limited to, admixing with a solidcatalyst source and impregnating the catalyst onto the carbonaceoussolid. Several impregnation methods known to those skilled in the artcan be employed to incorporate the gasification catalysts. These methodsinclude, but are not limited to, incipient wetness impregnation,evaporative impregnation, vacuum impregnation, dip impregnation, andcombinations of these methods. Gasification catalysts can be impregnatedinto the carbonaceous solids by slurrying with a solution (e.g.,aqueous) of the catalyst.

That portion of the particulate carbonaceous feedstock of a particlesize suitable for use in the gasifying reactor can then be furtherprocessed, for example, to impregnate one or more catalysts and/orco-catalysts by methods known in the art, for example, as disclosed inpreviously incorporated U.S. Pat. No. 4,069,304, U.S. Pat. No.4,092,125, U.S. Pat. No. 4,468,231, U.S. Pat. No. 4,551,155 and U.S.Pat. No. 5,435,940; and previously incorporated U.S. patent applicationSer. Nos. 12/234,012, 12/234,018, 12/342,565, 12/342,578, 12/342,608,12/343,159, 12/342,578 and 12/342,596.

One particular method suitable for combining the coal particulate with agasification catalyst to provide a catalyzed carbonaceous feedstockwhere the catalyst has been associated with the coal particulate via ionexchange is described in previously incorporated US2009/0048476A1. Thecatalyst loading by ion exchange mechanism is maximized (based onadsorption isotherms specifically developed for the coal), and theadditional catalyst retained on wet including those inside the pores iscontrolled so that the total catalyst target value is obtained in acontrolled manner. Such loading provides a catalyzed coal particulate asa wet cake. The catalyst loaded and dewatered wet coal cake typicallycontains, for example, about 50% moisture. The total amount of catalystloaded is controlled by controlling the concentration of catalystcomponents in the solution, as well as the contact time, temperature andmethod, as can be readily determined by those of ordinary skill in therelevant art based on the characteristics of the starting coal.

In embodiments of the invention, the entirety of the carbonaceousfeedstock need not be loaded with a gasification catalyst. In someembodiments, only a portion of the carbonaceous feedstock is loaded witha gasification catalyst. In such embodiments, the carbonaceous feedstock(part loaded and part unloaded) may optionally be dry mixed withgasification catalyst. In other embodiments, however, substantially allof the carbonaceous feedstock is loaded with gasification catalyst. Inthese embodiments, though, the loaded carbonaceous feedstock mayoptionally be dry mixed with an amount of gasification catalyst.

The catalyzed feedstock can be stored for future use or transferred to afeed operation for introduction into the gasification reactor. Thecatalyzed feedstock can be conveyed to storage or feed operationsaccording to any methods known to those skilled in the art, for example,a screw conveyer or pneumatic transport.

Steam Generation

The steam supplied to the gasification reactor can originate from avariety of sources, including commercial gasification reactors, oxy-fuelcombustors, and boilers. The gasification or combustion reaction of acarbonaceous feedstock generates large amounts of heat energy.Advantageously, this heat energy can be used to contact any type of heatexchanger which is also in contact with a water source, therebygenerating steam. For example, any of the boilers known to those skilledin the art can supply steam to the reactor. While any water source canbe used to generate steam, the water commonly used in known boilersystems is purified and deionized (about 0.3-1.0 microsiemens/cm) sothat corrosive processes are slowed. Such boilers can be powered, forexample, through the combustion of any carbonaceous material, includingpulverized/powdered coal, biomass, and rejected carbonaceous materialsfrom the feedstock preparation operation (e.g., fines, supra). Thethermal energy from the burning the carbonaceous material heats thewater in the boiler, which eventually converts into steam (at about 700°F. and 3,200 psi). The steam is routed from the boiler into heatedtubes, which are typically located in the furnace at or near the exitconduit carrying the combustion gases. The steam can be routed viaheated conduits to the gasification reactor, it can be used to dry acarbonaceous feedstock, or it can be prepared and routed to a steamturbine for generation of electricity. In order to avoid excessivecooling of the steam during transport, the heated conduits for carryingsteam can also be superheated (e.g., via contact with a heat exchanger)prior to delivery of the steam to its endpoint. Suitable methods ofsteam generation are described in previously incorporated U.S. patentapplication Ser. Nos. 12/395,309 and 12/395,320.

Steam can also be supplied from a second gasification reactor coupledwith a combustion turbine, the exhaust of which contacts a heatexchanger in contact with a water source, which can include a boilersystem as described above, to produce steam.

Recycled steam from other process operations can also be used forsupplying steam to the reactor. For example, when a slurriedcarbonaceous feedstock is dried with a fluid bed slurry drier, asdiscussed herein, the steam generated through vaporization can be fed tothe gasification reactor. Similarly, steam can be generated directlyfrom a slurry gasifier which produces steam and synthesis gas from anaqueous carbonaceous feed slurry, such as described in previouslyincorporated U.S. patent application Ser. No. 12/343,149. At least aportion of the steam can also be used to drive a steam turbine thatgenerates electricity.

Treatment of Crude Product Gas

Crude product gas effluent leaving the catalytic gasifier can passthrough a portion of the reactor which serves as a disengagement zonewhere particles too heavy to be entrained by the gas leaving the reactor(i.e., fines) are returned to the fluidized bed. The disengagement zonecan include one or more internal cyclone separators or similar devicesfor removing fines and particulates from the gas. The gas effluentpassing through the disengagement zone and leaving the catalyticgasifier generally contains CH₄, CO₂, H₂ and CO, H₂S, NH₃, unreactedsteam, entrained fines, and other contaminants such as COS.

The gas stream from which the fines have been removed can then be passedthrough a heat exchanger to cool the gas and the recovered heat can beused to preheat recycle gas and generate high pressure steam. Residualentrained fines can also be removed by any suitable means such asexternal cyclone separators, optionally followed by Venturi scrubbers.The recovered fines can be processed to recover alkali metal catalystthen passed to the slurry feedstock preparation process or returned tothe catalytic gasification reactor, or directly recycled back tofeedstock preparation as described in previously incorporated U.S.patent application Ser. No. 12/395,385.

The gas stream from which the fines have been removed is fed to a gaspurification operation optionally comprising COS hydrolysis reactors forCOS removal (sour process) and further cooled in a heat exchanger torecover residual heat. Methods for COS hydrolysis are known to thoseskilled in the art, for example, see U.S. Pat. No. 4,100,256.

Following COS removal, the gas stream generally contains CH₄, CO₂, H₂,CO, H₂S, NH₃, and steam. This gas stream can be further treated in awater scrubber for recovery of ammonia, yielding a scrubbed gas thatcomprises at least H₂S, CO₂, CO, H₂, and CH₄.

Scrubber water and sour process condensate can be processed to strip andrecover H₂S, CO₂ and NH₃; such processes are well known to those skilledin the art. NH₃ can typically be recovered as an aqueous solution (e.g.,20 wt %).

Carbon monoxide can be removed from a gas stream at any stage of theprocess by incorporating a sour gas shift reaction. Sour gas shiftinvolves reacting steam and CO at suitable conditions to yield CO₂ andH₂. This sour shift process is described in detail, for example, in U.S.Pat. No. 7,074,373. Its use within a catalytic gasification process isdescribed in previously incorporated U.S. patent application Ser. No.______ (attorney docket no. FN-0033, entitled “SOUR SHIFT PROCESS FORTHE REMOVAL OF CARBON MONOXIDE FROM A GAS STREAM”). The processtypically involves adding water, or using water contained in the gas,and reacting the resulting water-gas mixture adiabatically over a steamreforming catalyst. Typical steam reforming catalysts include one ormore Group VIII metals on a heat-resistant support. The sour gas shiftcan, for example, remove at least about 80%, or at least about 90%, orat least about 95%, or at least about 99%, of the CO in the treated gasstream.

Methods and reactors for performing the sour gas shift reaction on aCO-containing gas stream are, in a general sense, well known to those ofskill in the art. Suitable reaction conditions and suitable reactors canvary depending on the amount of CO that must be depleted from the gasstream. In some embodiments, the sour gas shift can be performed in asingle stage within a temperature range from about 100° C., or fromabout 150° C., or from about 200° C., to about 250° C., or to about 300°C., or to about 350° C. In these embodiments, the shift reaction can becatalyzed by any suitable catalyst known to those of skill in the art.Such catalysts include, but are not limited to, Fe₂O₃-based catalysts,such as Fe₂O₃—Cr₂O₃ catalysts, and other transition metal-based andtransition metal oxide-based catalysts. In other embodiments, the sourgas shift can be performed in multiple stages. In one particularembodiment, the sour gas shift is performed in two stages. Thistwo-stage process uses a high-temperature sequence followed by alow-temperature sequence. The gas temperature for the high-temperatureshift reaction ranges from about 350° C. to about 1050° C. Typicalhigh-temperature catalysts include, but are not limited to, iron oxideoptionally combined with lesser amounts of chromium oxide. The gastemperature for the low-temperature shift ranges from about 150° C. toabout 300° C., or from about 200° C. to about 250° C. Low-temperatureshift catalysts include, but are not limited to, copper oxides that maybe supported on zinc oxide or alumina.

Steam shifting is often carried out with heat exchangers and steamgenerators to permit the efficient use of heat energy. Shift reactorsemploying these features are well known to those of skill in the art. Anexample of a suitable shift reactor is illustrated in previouslyincorporated U.S. Pat. No. 7,074,373, although other designs known tothose of skill in the art are also effective.

A subsequent acid gas removal process can be used to remove H₂S and CO₂from the scrubbed gas stream by a physical absorption method involvingsolvent treatment of the gas to give a cleaned gas stream. Suchprocesses involve contacting the scrubbed gas with a solvent such asmonoethanolamine, diethanolamine, methyldiethanolamine,diisopropylamine, diglycolamine, a solution of sodium salts of aminoacids, methanol, hot potassium carbonate or the like. One method caninvolve the use of SELEXOL® (UOP LLC, Des Plaines, Ill. USA) orRECTISOL® (Lurgi AG, Frankfurt am Main, Germany) solvent having twotrains; each train consisting of an H₂S absorber and a CO₂ absorber. Thespent solvent containing H₂S, CO₂ and other contaminants can beregenerated by any method known to those skilled in the art, includingcontacting the spent solvent with steam or other stripping gas to removethe contaminants or by passing the spent solvent through strippercolumns. Recovered acid gases can be sent for sulfur recoveryprocessing; for example, any recovered H₂S from the acid gas removal andsour water stripping can be converted to elemental sulfur by any methodknown to those skilled in the art, including the Claus process. Sulfurcan be recovered as a molten liquid. Stripped water can be directed forrecycled use in preparation of the catalyzed feedstock. One method forremoving acid gases from the scrubbed gas stream is described inpreviously incorporated U.S. patent application Ser. No. 12/395,344.

Advantageously, CO₂ generated in the process, whether in the steamgeneration or catalytic gasification or both (and in the optional sourgas shift), can be recovered for subsequent use or sequestration,enabling a greatly decreased carbon footprint (as compared to directcombustion of the feedstock) as a result. Processes for reducing acarbon footprint are described in previously incorporated U.S. patentapplication Ser. Nos. 12/395,309 and 12/395,320.

The resulting cleaned gas stream exiting the gas purification operationcontains appreciable amounts of CH₄ and H₂ and, optionally, CO, and canalso contain small amounts of CO₂ and H₂O.

In accordance with the present invention, this cleaned gas stream can befurther processed to provide at least a partial separation of hydrogenfrom the other gaseous products in the gas stream. This results in theformation of a hydrogen-enriched gas stream and a hydrogen-depleted gasstream. The hydrogen-enriched gas stream comprises at least about 70 mol%, or at least about 80 mol %, or at least about 90 mol %, or at leastabout 97 mol %, hydrogen gas. In some embodiments, the hydrogen-enrichedgas stream substantially comprises hydrogen gas, having, for example, atleast about 90 mol % hydrogen gas. The hydrogen-depleted gas stream atleast comprises methane. In some embodiments, the hydrogen-depleted gasstream at least comprises methane and carbon monoxide, and can alsocomprise up to about 4 mol % hydrogen.

Various methods for effecting separation of hydrogen are known to thoseof skill in the art. Such methods include cryogenic separation andmembrane-based separation. For embodiments where the cleaned gas streamcomprises no appreciable amounts of carbon monoxide (e.g., less thanabout 1000 ppm CO), the separation can be effected through methodsinvolving the formation of methane hydrates, as illustrated inpreviously incorporated U.S. patent application Ser. No. 12/395,330.

The hydrogen-depleted gas stream at least comprises methane. In someembodiments, the hydrogen-depleted gas stream should have a heatingvalue of at least 950 btu/scf (dry basis). For example, in someembodiments, the hydrogen-depleted gas stream comprises at least about80 mol %, or at least about 90 mol %, or at least about 95 mol %methane. In some embodiments, however, the hydrogen-depleted gas streamat least comprises both methane and carbon monoxide, and optionally aminor amount of hydrogen (generally about 4 mol % or less). In some suchembodiments, the hydrogen-depleted gas comprises at least about 1000 ppmcarbon monoxide. In other embodiments, the hydrogen depleted gas streamis substantially free of carbon monoxide, having, for example, less thanabout 1000 ppm carbon monoxide.

In embodiments where the hydrogen-depleted gas stream comprises 1000 ppmor more carbon monoxide, and where the heating value of thehydrogen-depleted gas stream is less than 950 btu/scf (dry basis), themethane in the hydrogen-depleted gas stream and the carbon monoxide inthe hydrogen-depleted gas stream can be at least partially separatedfrom each other. This partial separation of methane and carbon monoxideyields at least a methane-enriched gas stream and a carbonmonoxide-enriched gas stream. The methane-enriched gas stream comprisesat least about 80 mol %, or at least about 90 mol %, or at least about95 mol % methane. Moreover, in typical embodiments, the methane-enrichedgas stream has a heating value of at least about 950 btu/scf (drybasis). The carbon monoxide-enriched gas stream comprises at least about50 mol %, or at least about 65 mol %, or at least about 80 mol %, or atleast about 90 mol %, carbon monoxide.

In embodiments of the invention where the separation yields amethane-enriched gas stream that substantially comprises methane, themethane stream can be recovered and used as a high-quality energysource. For example, the methane can be compressed and introduced intothe existing natural gas pipeline system. Or, a portion of the methaneproduct can also be used as plant fuel for a gas turbine.

In some embodiments, a methane-enriched gas stream (e.g., thehydrogen-depleted gas stream), if it contains appreciable amounts of CO,can be further enriched in methane by performing trim methanantion toreduce the CO content. One may carry out trim methanation using anysuitable method and apparatus known to those of skill in the art,including, for example, the method and apparatus disclosed in U.S. Pat.No. 4,235,044.

In embodiments of the invention where the separation yields ahydrogen-enriched gas stream that substantially comprises hydrogen, thehydrogen stream can be recovered and used as an energy source and/or asa reactant. For example, the hydrogen can be used as an energy sourcefor hydrogen-based fuel cells, or in a subsequent catalytic gasificationprocess.

In another example, hydrogen can be used as a fuel for a steamgeneration process, such as described in previously incorporated U.S.patent application Ser. Nos. 12/395,309 and 12/395,320; or as disclosedin previously incorporated U.S. patent application Ser. No. ______(attorney docket no. FN-0033, entitled “SOUR SHIFT PROCESS FOR THEREMOVAL OF CARBON MONOXIDE FROM A GAS STREAM”).

In embodiments of the invention where the separation yields a carbonmonoxide-enriched gas stream that substantially comprises carbonmonoxide, the carbon monoxide stream can be recovered and used as partof a fuel mixture (e.g., with hydrogen), or in a subsequent catalyticgasification process. The carbon monoxide gas stream can also becombined with hydrogen and used as fuel for a steam generation process,such as described in previously incorporated 12/395,309 and 12/395,320;or as disclosed in previously incorporated U.S. patent application Ser.No. ______ (attorney docket no. FN-0033, entitled “SOUR SHIFT PROCESSFOR THE REMOVAL OF CARBON MONOXIDE FROM A GAS STREAM”).

In some embodiments of the invention, the hydrogen is recycled back tothe catalytic gasifier, directly and/or via another unit operation suchas discussed below.

Continuous Gasification Process Employing Methane Separation Options

The invention also provides for a continuous catalytic gasificationprocess wherein hydrogen, and optionally, carbon monoxide, are recycledand used in the catalytic gasification processes.

1. Introduction of a Carbonaceous Feedstock to a Gasification Reactor

The processes of the invention require the supplying of a carbonaceousfeedstock and a gas feed (comprising steam, carbon monoxide andhydrogen) to a gasification reactor.

Suitable gasification reactors and carbonaceous feedstocks are describedabove. In typical embodiments, the carbonaceous feedstock is provided inparticulate form, although this need not be the case in all embodiments.In typical embodiments, the carbonaceous feedstock is loaded with, or atleast mixed with, a suitable gasification catalyst. Suitable catalystsare described above. Typical processes at least include potassiumcarbonate and/or potassium hydroxide.

In some embodiments, steam may also be introduced into the gasificationreactor in the same step as the introduction of the carbonaceousfeedstock. The steam can be generated by any suitable method for thegeneration of steam known to those of skill in the art. Suitable methodsof steam generation are described above.

In some embodiments, a stream of feed gases (in addition to the steam)can also be introduced into the gasification reactor within the samestep as the introduction of the carbonaceous feedstock. This feed gasstream at least comprises hydrogen and carbon monoxide, but can alsoinclude carbon dioxide and water vapor. The feed gas stream can begenerated in a variety of ways.

In some embodiments, the feed gas stream comprises the product ofreforming methane in a methane reformer. In a particular embodiment, theinput gases for the methane reformation are a portion of the methaneproduct of catalytic gasification of a carbonaceous feedstock. Themethane reacts in the methane reformer to generate a gas stream that atleast comprises carbon monoxide and hydrogen gas. This gas streamcomprising CO and H₂ can serve as a recycle gas stream (combined withthe hydrogen-enriched gas stream) that is introduced (i.e., recycled)into the gasification reactor as the product gas stream.

In some embodiments, the feed gas stream is the product of a combustionreaction. In a particular embodiment, the combustion reaction occurs ina reactor (e.g., an oxy-blown gasifier or a combustion reactor). Acarbonaceous feedstock is supplied to the reactor in the presence ofoxygen. The carbonaceous feedstock may or may not be in particulateform, and can have the same or different composition that thecarbonaceous feedstock used for the catalytic gasification. Thecombustion process typically yields a resulting gas stream that at leastcomprises CO, H₂ and CO₂, and H₂O if the combustion process is used togenerate steam. The combustion gas stream, in combination with thehydrogen enriched gas stream, can serve as a gas stream that isintroduced into the gasification reactor as the feed gas stream.

In some embodiments, the feed gas stream comprises hydrogen, andoptionally carbon monoxide, that are recovered from the cleaned gasstream of a previous catalytic gasification process. Suitable methodsfor separating and recovering hydrogen-enriched gas streams and carbonmonoxide-enriched gas streams are described herein.

In embodiments where the feed gas stream is the product of a combustionreaction, the heat energy from the combustion reaction can be used as aheat source for the steam generation process, described above.

2. Catalytic Gasification of Carbonaceous Feedstock

A carbonaceous feedstock is reacted in a gasification reactor in thepresence of the feed gas stream (including steam) and a gasificationcatalyst under suitable temperature and pressure to form a gas streamcomprising methane, hydrogen, carbon monoxide, carbon dioxide, and oneor more additional gaseous products. Catalytic gasification, includingsuitable reactors and reaction conditions, is described above.

3. Removal of CO₂ and Other Gaseous by-Products

Carbon dioxide and other gaseous by-products (e.g., hydrogen sulfide,ammonia, etc.) can be removed from the gas stream. Suitable methods forremoval of these gases from the gas stream are described above. Theseparation results in at least two gas streams. One gas streamsubstantially comprises one or more of hydrogen, methane, and carbonmonoxide. In typical embodiments, this gas stream comprises at leastabout 90 mol %, or at least about 95 mol %, or at least about 99 mol %,methane, hydrogen, and/or carbon monoxide. The relative proportions ofthese gases in the gas stream can vary depending on a variety offactors, including the gasification conditions and the nature of thecarbonaceous feedstock. The other gas stream comprises carbon dioxide.In some embodiments, the gas stream comprising carbon dioxide can berecovered and sequestered to provide for carbon footprint reduction.

4. Separation of Hydrogen from Gas Stream

After removal of CO₂ and other gaseous by-products, the gas streamcomprises hydrogen, methane and, optionally, carbon monoxide. Hydrogenis at least partially separated from the other gaseous products in thegas stream. This separation results in a hydrogen-enriched gas streamand a hydrogen-depleted gas stream. The hydrogen-enriched gas streamcomprises at least about 70 mol %, or at least about 80 mol %, or atleast about 90 mol %, or at least about 97 mol %, hydrogen gas. In someembodiments, the hydrogen-enriched gas stream substantially compriseshydrogen gas, having, for example, at least about 90 mol % hydrogen gas.The hydrogen-depleted gas stream at least comprises methane. In someembodiments, the hydrogen-depleted gas stream at least comprises methaneand carbon monoxide, and can also comprise up to about 4 mol % hydrogen.

Suitable means of separating hydrogen from a gas stream are describedabove.

In some embodiments, the hydrogen-enriched gas stream can be recoveredfollowing separation. In such embodiments, the invention includes anysuitable means of gas recovery known to those of skill in the art. Therecovery method and apparatus can vary depending on factors such as themeans used to effect separation and the desired use of the enriched gasstream following separation.

5. Separation of Methane and Carbon Monoxide

The hydrogen-depleted gas stream at least comprises methane. Forexample, in some embodiments, the hydrogen-depleted gas stream comprisesat least about 80 mol %, or at least about 90 mol %, or at least about95 mol % methane. In some embodiments, however, the hydrogen-depletedgas stream at least comprises both methane and carbon monoxide. In somesuch embodiments, the hydrogen-depleted gas comprises at least about1000 ppm carbon monoxide. In other embodiments, the hydrogen depletedgas stream is substantially free of carbon monoxide, having, forexample, less than about 1000 ppm carbon monoxide.

In embodiments where the hydrogen-depleted gas stream comprises 1000 ppmor more carbon monoxide and where the heating value of thehydrogen-depleted gas stream is less than 950 btu/scf (dry basis), themethane in the hydrogen-depleted gas stream and the carbon monoxide inthe hydrogen-depleted gas stream can be at least partially separatedfrom each other. This partial separation of methane and carbon monoxideyields at least a methane-enriched gas stream and a carbonmonoxide-enriched gas stream. The methane-enriched gas stream comprisesat least about 80 mol %, or at least about 90 mol %, or at least about95 mol % methane. Moreover, in typical embodiments, the methane-enrichedgas stream has a heating value of at least about 950 btu/scf (drybasis). The carbon monoxide-enriched gas stream comprises at least about50 mol %, or at least about 65 mol %, or at least about 80 mol % carbonmonoxide.

Suitable means of separating methane and carbon monoxide are describedabove.

In some embodiments, the methane-enriched gas stream and/or the carbonmonoxide-enriched gas stream can be recovered following separation. Insuch embodiments, the invention includes any suitable means of gasrecovery known to those of skill in the art. The recovery method andapparatus can vary depending on factors such as the means used to effectseparation and the desired use of the enriched gas stream followingseparation. For example, in embodiments where the methane-enriched gasstream substantially comprises methane, the methane-enriched gas streamcan be recovered by pressurizing the gas in a suitable pressurizingapparatus and introducing the pressurized methane into a network ofnatural gas pipelines.

Further process details can be had by reference to the previouslyincorporated patents and publications.

Pipeline Quality Natural Gas

The invention provides processes that, in certain embodiments, cangenerate pipeline-quality natural gas from the catalytic gasification ofa carbonaceous feedstock. A “pipeline-quality natural gas” typicallyrefers to a natural gas that is (1) within ±5% of the heating value ofpure methane (whose heating value is 1010 btu/ft³ under standardatmospheric conditions), and (2) free of water and toxic or corrosivecontaminants. In some embodiments of the invention, the methane-enrichedgas stream described in the above processes satisfies such requirements.

Pipeline-quality natural gas can contain gases other than methane, aslong as the resulting gas mixture has a heating value that is within ±5%of 1010 btu/ft³ and is neither toxic nor corrosive. Therefore, amethane-enriched gas stream can comprise gases whose heating value isless than that of methane and still qualify as a pipeline-qualitynatural gas, as long as the presence of the other gases does not lowerthe gas stream's heating value below 950 btu/scf (dry basis). Therefore,a methane-enriched gas stream can comprise up to about 4 mol % hydrogenand still serve as a pipeline-quality natural gas. Carbon monoxide has ahigher heating value than hydrogen. Thus, pipeline-quality natural gascould contain even higher percentages of CO without degrading theheating value of the gas stream. A methane-enriched gas stream that issuitable for use as pipeline-quality natural gas preferably has lessthan about 1000 ppm CO.

EXAMPLES

The following example illustrates one or more particular embodiments ofthe invention. The example provides merely one or more embodiments ofthe claimed invention, and is not intended to be limiting in any manner.

Example 1 Continuous Process Employing Methane Separation Options

FIG. 1 illustrates several embodiments of a continuous processencompassed by the present invention. A quantity of feedstock can beprepared by wet grinding it into a fine particulate using a wet grinder.After grinding, the feedstock should have a particle size ranging fromabout 45 μm to about 2500 μm. The feedstock can be removed from thegrinder and introduced to a catalyst loading unit (e.g., one or moreslurry tanks), where gasification catalyst can be loaded onto thefeedstock particulate. The loaded catalyst can comprise a mixture ofcatalyst recovered from a previous gasification process and raw make-upcatalyst. After catalyst is loaded onto the feedstock particulate, thecatalyst-loaded feedstock can be introduced into a gasification reactor(1).

The feedstock should be converted in the gasification reactor (1), inthe presence of steam, to a plurality of gaseous products comprising atleast CH₄, CO₂, H₂, CO, H₂S, NH₃, steam, and COS. The COS can be removedthrough a hydrolysis process carried out in a hydrolysis reactor (notshown). Then, ammonia can be removed by scrubbing the gas in amulti-unit scrubber apparatus (shown as part of a generic separationapparatus (2)). Then, CO₂ and H₂S can be substantially removed from thegas stream in an acid gas removal process involving the exposure of thegas stream to a solvent in a solvent treatment vessel (shown as part ofa generic separation apparatus (2)). At this point, the gas streamshould substantially comprise methane, carbon monoxide, and hydrogen.

Optionally, a sour shift reactor can be utilized prior to the acid gasremoval process to convert substantially all of the CO (in the presenceof steam) to CO₂ and H₂. In this instance, the gas stream after the acidgas removal process should substantially comprise methane and hydrogen.

The hydrogen gas can be substantially separated from the methane andcarbon monoxide by passing the gas stream through a membrane separator(3). Two gas streams (8, 9) emerge from the membrane separator. One gasstream should substantially comprise hydrogen (8). The other gas streamshould substantially comprise methane and carbon monoxide (9).

The methane and carbon monoxide can be separated from each other byseveral available means. In a first option, the gas mixture can beintroduced to a cryogenic separator (4), which effects separation of thegases into a gas stream that substantially comprises methane and anothergas stream that substantially comprises carbon monoxide (7). In a secondoption, the gas mixture can be introduced to a methane hydrate separator(5), which effects separation of the gases into a gas stream thatsubstantially comprises methane and another gas stream thatsubstantially comprises carbon monoxide (7). In a third option, the gasmixture can be purified by introducing the gas mixture into a trimmethanation reactor, such as described above. Each of these separationmethods is described in greater detail above and in the provisionalapplications incorporated by reference.

The methane gas stream can be recovered and used for pipeline gradenatural gas. The hydrogen gas stream (8) can be combined with the carbonmonoxide gas stream (6) and recycled into the gasification reactor to beused in a subsequent catalytic gasification process.

1. A process for converting a carbonaceous feedstock into a plurality ofgaseous products contained in a gas stream, and for separating hydrogenand methane from the gas stream, the process comprising the steps of:(a) supplying a carbonaceous feedstock to a gasification reactor; (b)reacting the carbonaceous feedstock in the gasification reactor in thepresence of steam and a gasification catalyst and under suitabletemperature and pressure to form a first gas stream comprising methane,hydrogen, carbon monoxide, carbon dioxide, and one or more additionalgaseous by-products; (c) removing a substantial portion of the carbondioxide and a substantial portion of the one or more additional gaseousby-products from the first gas stream to produce a second gas streamcomprising methane, hydrogen, and optionally carbon monoxide; (d) atleast partially separating hydrogen from the second gas stream to form ahydrogen-enriched gas stream and a hydrogen-depleted gas stream, whereinthe hydrogen-depleted gas stream comprises methane, optionally carbonmonoxide and up to about 4 mol % hydrogen; wherein, if the heating valueof the hydrogen-depleted gas stream is less than 950 btu/scf (drybasis), and if the hydrogen-depleted gas stream comprises 1000 ppm ormore of carbon monoxide: (1) at least partially separating carbonmonoxide from the hydrogen-depleted gas stream to form (i) a carbonmonoxide-enriched gas stream and (ii) a methane-enriched gas streamhaving a heating value of at least 950 btu/scf (dry basis); or (2) atleast partially methanating the carbon monoxide in the hydrogen-depletedgas stream to form a methane-enriched gas stream.
 2. The process ofclaim 1, wherein the second gas stream comprises carbon monoxide, andthe hydrogen-depleted gas stream comprises at least about 1000 ppmcarbon monoxide.
 3. The process of claim 2, wherein the carbon monoxidein the hydrogen-depleted gas stream is at least partially methanated toform a methane-enriched gas stream.
 4. The process of claim 1, whereinthe gasification catalyst is an alkali metal gasification catalyst. 5.The process of claim 4, wherein the alkali metal is potassium.
 6. Theprocess of claim 1, wherein the hydrogen is separated by passing thesecond gas stream through a hydrogen membrane separator.
 7. A processfor converting a carbonaceous feedstock into a plurality of gaseousproducts contained in a gas stream, and for separating hydrogen andmethane from the gas stream, the process comprising the steps of: (a)supplying a first carbonaceous feedstock to a reactor; (b) at leastpartially combusting the first carbonaceous feedstock in the reactor inthe presence of oxygen and under suitable temperature and pressure so asto generate (i) heat energy and (ii) a combustion gas stream comprisinghydrogen, carbon monoxide, and carbon dioxide; (c) using the heat energyfrom the combustion of the first carbonaceous feedstock to generatesteam; (d) introducing at least a portion of the steam, at least aportion of the combustion gas stream, a second carbonaceous feedstockand a gasification catalyst to a gasification reactor; (e) reacting thesecond carbonaceous feedstock in the gasification reactor in thepresence of steam and the gasification catalyst under suitabletemperature and pressure to form a first gas stream comprising methane,hydrogen, carbon monoxide, carbon dioxide and one or more additionalgaseous by-products; (f) removing a substantial portion of the carbondioxide and a substantial portion of the one or more gaseous by-productsfrom the first gas stream to produce a second gas stream comprisingmethane, hydrogen and optionally carbon monoxide; (g) at least partiallyseparating hydrogen from the second gas stream to form ahydrogen-enriched gas stream and a hydrogen-depleted gas stream, whereinthe hydrogen-depleted gas stream comprises methane, optionally carbonmonoxide and up to about 4 mol % hydrogen; wherein, if the heating valueof the hydrogen-depleted gas stream is less than 950 btu/scf (drybasis), and if the hydrogen-depleted gas stream comprises 1000 ppm ormore of carbon monoxide: (1) at least partially separating carbonmonoxide from the hydrogen-depleted gas stream to form (i) a carbonmonoxide-enriched gas stream and (ii) a methane enriched gas streamhaving a heating value of at least 950 btu/scf (dry basis); or (2) atleast partially methanating the carbon monoxide in the hydrogen-depletedgas stream to form a methane-enriched gas stream.
 8. The process ofclaim 7, wherein the first carbonaceous feedstock and the secondcarbonaceous feedstock have substantially the same composition.
 9. Theprocess of claim 7, wherein the first carbonaceous feedstock and thesecond carbonaceous feedstock have different compositions.
 10. Theprocess of claim 7, wherein the first carbonaceous feedstock, the secondcarbonaceous feedstock, or both the first carbonaceous feedstock and thesecond carbonaceous feedstock are in a particulate form.
 11. The processof claim 7, wherein the first carbonaceous feedstock is in the form ofan aqueous slurry.
 12. The process of claim 7, wherein the reactor iseither a gasification reactor or an oxygen combustor.
 13. The process ofclaim 7, wherein, in step (c), the steam is generated within thereactor.
 14. The process of claim 14, wherein, in step (c), the heatenergy is transferred to a heat exchanger which generates steam uponcontact with water.
 15. The process of claim 7, wherein substantiallyall of the steam generated in step (c) is introduced into thegasification reactor.
 16. The process of claim 7, wherein the second gasstream comprises carbon monoxide, and the hydrogen-depleted gas streamcomprises at least about 1000 ppm carbon monoxide.
 17. The process ofclaim 16, wherein the carbon monoxide in the hydrogen-depleted gasstream is at least partially methanated to form a methane-enriched gasstream.
 18. The process of claim 7, wherein the gasification catalyst isan alkali metal gasification catalyst.
 19. The process of claim 18,wherein the alkali metal is potassium.
 20. The process of claim 7,wherein the hydrogen is separated by passing the second gas streamthrough a hydrogen membrane separator.